Using fossil fuels to increase biomass-based fuel benefits

ABSTRACT

In the production of fuel such as ethanol from carbonaceous feed material such as biomass, a stream comprising hydrogen and carbon monoxide is added to the raw gas stream derived from the feed material, and the resulting combined stream is converted into fuel and a gaseous byproduct such as by a Fischer-Tropsch reaction. The gaseous byproduct may be utilized in the formation of the aforementioned stream comprising hydrogen and carbon monoxide.

This application claims priority from U.S. Provisional Application Ser.No. 61/311,539, filed Mar. 8, 2010, the entire content of which ishereby incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to improvements in the production ofliquid fuels from solid feedstock such as biomass, coal, petroleum cokeand the like.

BACKGROUND OF THE INVENTION

Liquid fuels can be derived from solid feedstock materials by a seriesof operations including treatment of the feedstock to produce a feedstream that is then treated to form the desired product fuel. For thecase of biomass, treatment of the feed stream can involve fermentationreactions and/or can involve catalyzed synthesis of fuels fromprecursors such as hydrogen and carbon monoxide in the feed stream. Thepresent invention provides improvements in the efficiency of productionof liquid fuels from the biomass as well as coal, petroleum coke and thelike.

BRIEF SUMMARY OF THE INVENTION

One aspect of the invention is a method, which can be adapted to usefossil fuels to increase the beneficial impact of liquid hydrocarbonfuels derived from biomass or other carbonaceous feed material on carbondioxide emissions derived from use of fossil-based liquid hydrocarbonfuels, comprising

(A) providing fossil-fuel hydrocarbon feed;

(B) forming from said fossil-fuel hydrocarbon feed a gaseous productstream comprising hydrogen and carbon monoxide at a mole ratio of H2:COof at least 2.0:1;

(C) adding the gaseous product stream formed in step (B) to a syngasstream containing hydrogen and CO that is derived from carbonaceous feedmaterial, in a sufficient amount to form a mixed syngas stream having aH2:CO mole ratio greater than that of said syngas stream derived fromcarbonaceous feed material;

(D) converting said mixed syngas stream to form product fuel andrecovering from said converting a byproduct stream comprising one ormore of hydrogen, CO, water vapor, methane, and hydrocarbons containing2 to 8 carbon atoms and 0 to 2 oxygen atoms; and

(E) reacting up to 100% of said byproduct stream in said formation ofsaid gaseous product stream in step (B).

One preferred embodiment of the invention is a method for improving thecarbon conversion efficiency of fuel production from carbonaceous feedmaterial, comprising

(A) deriving a raw gaseous stream comprising hydrogen and carbonmonoxide in a mole ratio of hydrogen:carbon monoxide of less than 2:1from carbonaceous feed material;

(B) forming a second gaseous stream comprising hydrogen and carbonmonoxide in a mole ratio of hydrogen:carbon monoxide greater than 2:1and also comprising carbon dioxide, and combining said second gaseousstream and the stream derived in step (A);

(C) converting said combined stream into product liquid fuel, and agaseous byproduct mixture comprising hydrogen, carbon monoxide, watervapor and methane;

(D) reacting hydrocarbon fuel and steam to form said second gaseousstream, wherein at least a portion of said gaseous byproduct mixture iscombusted to produce heat which is consumed in said reaction.

Other embodiments of the invention described herein include:

(I-A) A method comprising

(A) providing a gaseous product stream which is formed fromfossil-fuel-based hydrocarbon feed and which comprises hydrogen andcarbon monoxide at a mole ratio of H2:CO of at least 2.0:1; and

(B) adding the gaseous product stream provided in step (A) to a syngasstream derived from carbonaceous feed material and containing hydrogenand CO, in a sufficient amount to form a mixed syngas stream having aH2:CO mole ratio higher than that of said syngas stream derived fromcarbonaceous feed material.

(I-B) The foregoing method (I-A), wherein up to 100% of a byproductstream obtained from the conversion of said mixed syngas stream to formproduct fuel is reacted in said formation of said gaseous product streamthat is provided in step (A), wherein said byproduct stream comprisesone or more of hydrogen, CO, water vapor, methane and hydrocarboncontaining at least 2 carbon atoms and 0 to 2 oxygen atoms.

(II-A) A method comprising

(A) providing fossil-fuel-based hydrocarbon feed;

(B) forming from said fossil-fuel-based hydrocarbon feed a gaseousproduct stream comprising hydrogen and carbon monoxide at a mole ratioof H2:CO of at least 2.0:1; and

(C) adding the gaseous product stream formed in step (B) to a syngasstream containing hydrogen and CO that is derived from carbonaceous feedmaterial, in a sufficient amount to form a mixed syngas stream having aH2:CO mole ratio higher than that of said syngas stream derived fromcarbonaceous feed material.

(II-B) The foregoing method (I-A) also including the step of

(D) reacting up to 100% of a byproduct stream obtained from theconversion of said mixed syngas stream to form product fuel in saidformation of said gaseous product stream in step (B), wherein saidbyproduct stream comprises one or more of hydrogen, CO, water vapor,methane and hydrocarbon containing at least 2 carbon atoms and 0 to 2oxygen atoms.

(III-A) A method comprising

(A) deriving a syngas stream from carbonaceous feed material, whereinthe syngas stream contains hydrogen and CO; and

(B) adding to the syngas stream derived in step (A) a gaseous productstream comprising hydrogen and carbon monoxide, wherein the mole ratioof H2:CO of said gaseous product stream is at least 2.0:1, and whereinsaid gaseous product stream is formed from fossil-fuel-based hydrocarbonfeed,

wherein adding said gaseous product stream to said syngas stream forms amixed syngas stream having a H2:CO mole ratio higher than that of saidsyngas stream derived from carbonaceous feed material.

(III-B) The foregoing method (III-A), wherein up to 100% of a byproductstream obtained from the conversion of said mixed syngas stream to formproduct fuel is reacted in said formation of said gaseous product streamthat is added in step (B), wherein said byproduct stream comprises oneor more of hydrogen, CO, water vapor, methane and hydrocarbon containingat least 2 carbon atoms and 0 to 2 oxygen atoms.

As used herein, “fossil fuel” means product useful as fuel that iseither found in deposits in the earth and used in the form as found, orproduced by separatory and/or chemical processing of product that isfound in deposits in the earth.

As used herein, “product fuel” means hydrocarbon material (whichincludes oxygenated hydrocarbon material) useful as fuel and containingproduct selected from the group consisting of alkanes liquid at 25 C andatmospheric pressure, alkanols liquid at 25 C and atmospheric pressure,and mixtures thereof.

As used herein, “biomass” means algae or material containing any ofcellulose or hemicellulose or lignin, including but not limited toMunicipal Solid Waste (MSW), wood (including cut timber; boards, otherlumber products, and finished wooden articles, and wood waste includingsawdust), and vegetable matter such as grasses and other crops, as wellas products derived from vegetable matter such as rice hulls, ricestraw, soybean residue, corn stover, and sugarcane bagasse.

As used herein, “carbon conversion efficiency” means the fraction of thetotal carbon in carbonaceous feed material feedstock that is convertedto product fuel.

As used herein, “carbonaceous feed material” means biomass, coal of anyrank (including anthracite, bituminous, and lignite), coke produced fromcoal of any rank, petroleum coke, or bitumen.

A unique characteristic of the subject invention relates to the use ofthe fossil based syngas of step (B) to enhance the startup andoperability of the entire liquid production system. Biomass derived aswell as coal derived syngas involve the conversion of solids to syngas.Because of difficulties associated with handling and processing ofsolids and because of the high operating temperatures of technologies toconvert solids to syngas (generally called gasification technologies) itis rare for syngas production systems to perform at a high level ofsyngas availability (% of nameplate capacity actually available over agiven period of time—normally an annual average is used.) Typically asingle train gasification facility will have an annual availability ofless than about 90%. Higher availabilities are desired to increase theproduct income to offset the capital cost of the overall project.Typically a second and even a third gasification unit (two operating andone spare) are included in the project to improve overall productavailability and project economics. The inclusion of additional solidsprocessing and gasification trains is capital intensive. In addition,conventional gasification systems for liquids production are generallydesigned with startup/auxiliary boilers to provide steam required forinitiating unit operations such as feedstock drying, acid gas removalsystem solvent regeneration, and gasification where steam is often usedas a moderator to control gasifier temperatures. Startup boilers add tothe cost of the overall project. To achieve a higher level ofavailability at a lower capital cost and/or to minimize the capital costassociated with auxiliary (startup) boiler systems implementation of thesubject invention can include providing:

-   -   a quantity of the syngas formed from the fossil-fuel hydrocarbon        feed in sufficient volumes to maintain operation of the fuel        production (step D) when the syngas from the gasification of        carbonaceous feed material is unavailable.    -   a quantity of syngas formed from the fossil-fuel hydrocarbon        feed in sufficient amounts to provide for startup of the        facility—startup of step (D) fuel generation and providing steam        and heat requirements for startup of gasification of        carbonaceous feed material (steam addition to gasifier) unit        including drying as needed (drying of biomass if the facility is        a biomass gasification unit.)

Thus, additional embodiments of the present invention include thefollowing (IV-A) and (IV-B):

(IV-A) A method, comprising

(A) providing fossil-fuel hydrocarbon feed;

(B) forming from said fossil-fuel hydrocarbon feed a gaseous productstream comprising hydrogen and carbon monoxide at a mole ratio of H2:COof at least 2.0:1, and preferably 2.0:1 to 10:1;

(C) converting up to all of said gaseous product stream to form productfuel and recovering from said converting a byproduct stream comprisingone or more of hydrogen, CO, water vapor, methane, and hydrocarbonscontaining 2 to 8 carbon atoms and 0 to 2 oxygen atoms; and

(D) reacting up to 100% of said byproduct stream in said formation ofsaid gaseous product stream in step (B);

without adding to said gaseous product stream any other gaseous productderived from carbonaceous feed material; and thereafter

(E) adding to the gaseous product stream formed in step (B) a syngasstream containing hydrogen and CO that is derived from carbonaceous feedmaterial, in a sufficient amount to form a mixed syngas stream having aH2:CO mole ratio greater than that of said syngas stream derived fromcarbonaceous feed material;

(F) converting said mixed syngas stream to form product fuel andrecovering from said converting a byproduct stream comprising one ormore of hydrogen, CO, water vapor, methane, and hydrocarbons containing2 to 8 carbon atoms and 0 to 2 oxygen atoms; and

(G) reacting up to 100% of said byproduct stream in said formation ofsaid gaseous product stream in step (B).

This embodiment (IV-A) is encountered, for example, in starting up theoverall fuel production operation. In this and similar situations,syngas that is processed to produce fuel is produced from fossil-fuelhydrocarbon feed, such as in a steam-methane reformer, and contains nosyngas from carbonaceous feed material (such as biomass). Thereafter,syngas derived from carbonaceous feed material is added to the syngasfrom fossil fuel and the resulting combined syngas is fed to the fuelproduction unit.

(IV-B) A method wherein steps (A) through (G) of (IV-A) above arepreceded by the steps of

(a) providing fossil-fuel hydrocarbon feed;

(b) forming from said fossil-fuel hydrocarbon feed a gaseous productstream comprising hydrogen and carbon monoxide at a mole ratio of H2:COof at least 2.0:1;

(c) adding the gaseous product stream formed in step (b) to a syngasstream containing hydrogen and CO that is derived from carbonaceous feedmaterial, in a sufficient amount to form a mixed syngas stream having aH2:CO mole ratio greater than that of said syngas stream derived fromcarbonaceous feed material;

(d) converting said mixed syngas stream to form product fuel andrecovering from said converting a byproduct stream comprising one ormore of hydrogen, CO, water vapor, methane, and hydrocarbons containing2 to 8 carbon atoms and 0 to 2 oxygen atoms; and

(e) reacting up to 100% of said byproduct stream in said formation ofsaid gaseous product stream in step (b).

This embodiment (IV-B) is encountered, for example, in operation of theoverall fuel production operation, when feed of syngas derived from thecarbonaceous feed material and combining with the syngas formed fromfossil-fuel hydrocarbon feed is interrupted. In this and similarsituations, syngas that is processed to produce fuel is mixed syngasfrom both fossil-fuel and carbonaceous feed material, then does notinclude syngas from carbonaceous feed material, and then again includessyngas derived from carbonaceous feed material. The higher availabilityprovided by the use of gaseous or liquid feeds to produce the syngas inunit (D) derive from the well established availabilities of the syngasproducing technologies; steam methane reforming, autothermal reforming,steam methane reforming with secondary reforming, and partial oxidationunits based on light hydrocarbon feeds.

In preferred operations, in which the stream that is converted to formfuel includes syngas derived from carbonaceous feed material, the syngasstream formed from fossil fuel in step (B) can range between 5 mole % to75 mole % of the total syngas flow to step (D). Preferably, the syngasstream from fossil fuel formed in step (B) would range between 25 mole %to 65 mole % of the total syngas flow to step (D).

In the following description, disclosure of treatment of “a stream”,such as disclosure that a stream is reacted or otherwise processed, orthat a stream is fed to a processing step or is combined with anotherstream, is intended to include the indicated treatment of all or lessthan all of the stream, except where indicated otherwise herein.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a flowsheet showing one embodiment of a method for producingfuel from biomass, incorporating the present invention.

FIG. 2 is a flowsheet showing an alternative embodiment of the presentinvention.

FIG. 3 is a flowsheet showing another alternative embodiment of thepresent invention.

FIG. 4 is a flowsheet showing another alternative embodiment of thepresent invention.

FIG. 5 is a flowsheet showing another alternative embodiment of thepresent invention.

FIG. 6 is a flowsheet showing a comparative embodiment of a method ofproducing fuel from biomass.

FIG. 7 is a flowsheet showing another alternative embodiment of thepresent invention.

DETAILED DESCRIPTION OF THE INVENTION

The following description will refer to embodiments in which biomassfeed material is treated by gasification to produce fuels and especiallyalcohols and diesel. Those skilled in the art will recognize that thisembodiment can be suitably extended to other carbonaceous feedstocks,e.g. coal, coke, petroleum coke, as well as to the production ofgasoline and other Fischer Tropsch liquids. Also, this invention can beadapted to treatment of syngas derived from biomass by reactiontechnology other than gasification of the biomass, such as byfermentation of biomass. Where the following description refers togasification of biomass, it should not be limited to gasification exceptwhere specifically indicated.

Referring to FIG. 1, stream 1 of biomass is fed to unit 2 which may be agasification unit. Gasification stream 3 is also fed to gasificationunit 2. Stream 3 typically contains air, steam, or oxygen, or two or allthree of air, steam and oxygen. Unit 2 may comprise one gasificationreactor or a connected series of stages which overall achieve thedesired gasification, that is, the formation of a gaseous stream 5 whichcontains (at least) hydrogen and carbon monoxide and which typicallycontains other substances such as carbon dioxide, water vapor,hydrocarbons (including methane), volatilized tars, particulate matter,and sulfides.

Typically, unit 2 comprises a moving bed gasifier, such as Lurgi®gasifiers or a fluidized bed gasifier, such as the one developed bySilvagas or GTI. Another useful type of gasifier for the biomassapplication, especially MSW, is the plasma-based gasifiers. A discussionof biomass gasifiers can be found in the open literature, e.g. A Surveyof Biomass Gasification by Reed & Gaur, 2001. These biomass gasifiersproduce synthesis gas which includes hydrogen and carbon monoxide at amolar ratio (hydrogen:carbon monoxide) of less than 2:1. The hydrogenand the carbon monoxide are generated by breakdown of the biomassmaterial under conditions such that there is not complete oxidation towater and carbon dioxide. Gasification stream 3, which preferablycontains steam and oxygen, is fed into the bed so that it passes throughthe biomass and contacts the biomass, heats the biomass, and promotesthe aforementioned breakdown of the biomass material. Gasificationstream 3 is typically fed at a temperature in the range of 100° F. to750° F. and a pressure of 30 psia to 550 psia.

Within a moving bed gasifier, different reaction zones may be presentfrom top to bottom, namely a drying zone where moisture is released, adevolatilization zone where pyrolysis of biomass takes place, areduction zone where mainly the endothermic reactions occur, anexothermic oxidation or combustion zone, and an ash bed at the bottom ofthe gasifier. If the gasification stream contacts the biomass in acountercurrent fashion, hot dry devolatilized biomass reacts with therelatively cold incoming gasification stream, and hot raw gas beforeexiting as stream 5 exchanges heat with relatively cold incomingbiomass.

The temperature profile in each part of a gasifier varies as the biomassmoves through the different zones in the gasifier. In the gasificationzone the temperature may vary between 1400° F. and 2200° F. The gasstream 5 that is produced and leaves the gasification unit 2 istypically at a temperature of between about 1000° F. and 1600° F.

In fluid bed gasifiers the biomass solids are effectively completelymixed. The temperature in all parts of the bed are essentially the sameand can range from about 1200° F. and 1600° F. The gas stream 5 that isproduced and leaves the gasification unit 2 is typically at atemperature of between about 1200° F. and 1600° F.

As stream 5 typically includes substances that should not be present inthe stream 19 which is fed to reactor 8 as described below, stream 5 ispreferably treated in conditioning stage 4 to remove impurities 7 thatmay be present such as particulates, tars, acid gases including CO₂,ammonia, sulfur species, and other inorganic substances such as alkalicompounds. Impurities may be removed in one unit or in a series of unitseach intended to remove different ones of these impurities that arepresent or to reduce specific contaminants to the desired low levels.Unit 4 represents the impurities removal whether achieved by one unit orby more than one unit. This unit also includes the required cooling ofthe syngas. This energy can be recovered for use in other parts of theprocess. Details are not shown, but should be obvious to those skilledin the art. Use of a high temperature gasifier, e.g. plasma gasifier,where the syngas exits at >2000° F., reduces the complexity of unit 4.In particular, tar and methane content of syngas from high temperaturegasifiers tends to be quite low to non-existent. Unit 4 thus mayprimarily entail cooling/heat recovery.

The primary benefits of a fluidized bed gasifier are high heat transferrates, fuel flexibility and the ability to process feedstock with highmoisture content. A variety of fluidized bed gasifiers have been andcontinue to be used/developed for biomass gasification. Key processparameters include type of particle, size of particle and manner offluidization. Examples of configurations deployed for the biomassgasification application include the bubbling fluidized bed, wherebubbles of gas pass through the solids, to circulating fluidized bed,where the particles are carried out with the gas, subsequently separatedby a cyclone and returned to the gasifier. Fluidized bed gasifiers areoperated below the ash fusion temperature of the feedstock. Thegenerated syngas will contain impurities and thus will requireconditioning similar to the moving bed gasifier described above. Tarlevels may be less but still not quite as low as that from a plasmagasifier.

The resulting conditioned gaseous stream 9 from stage 4 contains atleast hydrogen and carbon monoxide, in a molar ratio of hydrogen tocarbon monoxide of less than 2:1. The exact composition can vary widelydepending on the biomass feedstock, gasifier type and operatingconditions. Stream 9 typically contains (on a dry basis) 20 to 50 vol. %of hydrogen, and 10 to 45 vol. % of carbon monoxide. Stream 9 typicallyalso contains carbon dioxide in amounts from 3 to 35 vol. %.

Before stream 9 is fed to reactor 8, it is combined with stream 11 whichis formed in reactor 6. Reactor 6 is preferably a steam methane reformerin which hydrocarbon fuel stream 13 that comprises fossil fuel 13 (e.g.natural gas, methane, naphtha, liquefied petroleum gases (LPG),preferably comprising product containing up to 8 carbon atoms) and steam15 are fed into a reactor where they react to form gaseous productstream 11 of syngas which contains hydrogen and carbon monoxide in amolar ratio (hydrogen:carbon monoxide) of at least 2:1, preferably 2.5:1to 10:1, and more preferably 3:1 or 4:1 to 8:1. The ratio of hydrogen tocarbon monoxide in the stream 11 that is produced in reactor 6 dependson the ratio of steam to carbon fed to reactor 6 and the temperature ofthe gas leaving the reactor. Increasing the pressure within reactor 6increases “methane slip” (level of unconverted hydrocarbons) and watervapor content in stream 11, both of which are undesirable. Increasingthe ratio of steam to carbon fed to reactor 6 increases the ratio ofhydrogen to carbon monoxide in stream 11, but can increase the overallenergy requirements of the system (taking into account the incrementaladditional energy required to produce additional steam that is fed toreactor 6).

Gas stream 11 can be generated within a steam methane reformer byintroducing the fossil-fuel hydrocarbon containing feed, typicallynatural gas, into steam methane reformer tubes located in a radiantsection of the steam methane reformer. The reformer tubes are packedwith a catalyst that is used to promote the steam methane reformingreactions. Steam methane forming reactions are endothermic and hence,heat is supplied to the reformer tubes to support the reactions byburners firing into the radiant section of the steam methane reformer.In steam methane reforming, the hydrocarbon containing stream, steamand, optionally, a recycle stream, is fed into a reactor. Commonly thereactor is formed by a bundle of tubes containing a catalyst. The tubebundle is located in a furnace and natural gas is also used as a fuel tothe furnace. The following reactions take place inside the catalystpacked tubes:CH₄+H₂O=>CO+3H₂CH₄+CO₂=>2CO+2H₂CO₂+H₂=>CO+H₂OThe crude synthesis gas product from the reactor, which containshydrogen, carbon monoxide, and water, is cooled down to avoid there-forming of methane from the carbon monoxide and the hydrogen.

When reactor 6 is a steam methane reformer, the product gas leaves thereformer at a temperature of about 1600° F., in which case the molarratio of steam to carbon fed to reactor 6 should be in the range of2.5:1 to 6:1 or even 2.0:1 to 6:1. The pressure within reactor 6 shouldbe less than 400 psia, preferably 200 psia or lower. Another factorconsidered when selecting the operating pressure of the steam methanereformer is to ensure that it is above or near the pressure of thebiomass-derived raw gaseous stream 9. Thus, stream 9 may optionally becompressed to the pressure of stream 11.

While it is preferable to deploy a steam methane reformer for reactor 6,it is recognized that it may be possible to practice some variations.Gas stream 11 can also be generated in a partial oxidation reactor byreaction between hydrocarbon and oxidant (e.g. oxygen), or in anautothermal reformer by reaction between hydrocarbon, oxidant and steam.In the autothermal reformer, oxygen reacts with hydrocarbons within anatural gas and steam containing feed to supply heat to support thesteam methane reforming reactions in a catalyst filled zone.

In a partial oxidation reaction, the hydrocarbon containing stream, forinstance, natural gas and oxygen are introduced into a partial oxidationreactor with the use of a specially designed burner. The oxygen isconsumed at the reactor entrance. The residence time in the reactor istypically about 3 seconds. The overall reaction that takes place is:CH₄+2O₂=>CO₂+2H₂O

The initial reaction is exothermic and produces heat and consequentialtemperature increases to above about 1300 degree. C. The hightemperatures allow the following reforming reactions to occur without acatalyst at the main part of the reactor:CH₄+H₂O=>CO+3H₂CH₄+CO₂=>2CO+2H₂CO₂+H₂=>CO+H₂O

In autothermal reforming, in a first reaction zone formed by a burner,natural gas, oxygen and, optionally, steam and a recycle streamcontaining carbon dioxide are reacted. The reaction in this firstreaction zone is as follows:CH₄+2O₂=>CO₂+2H₂O

The resultant intermediate product from the first reaction zonecontaining methane, water, and carbon dioxide, is fed to a catalyst bedbelow the burner where the final equilibration takes place in thefollowing reactions:CH₄+H₂O=>CO+3H₂CO₂+H₂=>CO+H₂OCH₄+CO₂=>2CO+2H₂The catalyst bed may be a vessel filled with catalyst as disclosed inU.S. Pat. No. 5,554,351 or a fluid bed catalyst system such as disclosedin U.S. Pat. No. 4,888,131. In the fluid bed system disclosed in theaforesaid patent, methane and steam are fed to the bottom of the fluidbed and oxygen is fed close to the bottom but inside the fluid bed. Thecrude synthesis gas can be treated in separation systems such as havebeen discussed above with respect to partial oxidation units.

The reforming reaction of steam and the hydrocarbon fossil fuel (e.g.natural gas, methane, naphtha, LPG) consumes energy, typically providedas heat from combustion of fuel fed as stream 14 with air, oxygen, oroxygen-enriched air fed as stream 16. Combustion creates flue gas stream20.

Table 1 quantifies the impact of the ratio of steam in stream 15 tocarbon in feed stream 13, on the composition of the gas stream 11 thatis produced in reactor 6, which is assumed to be a steam methanereformer assumed to operate at about 1600° F. and 100 psia (refer toFIG. 1). Lower steam to carbon ratios are envisioned when lower H₂/COratios are needed the addition of CO₂ to stream 13 has a similar effecton H₂/CO ratios.

TABLE 1 Impact of steam to methane ratio on syngas composition (ratiosare mole ratios) Steam to carbon Syngas comp. (mol. frac., dry basis)H₂/CO ratio H₂ CO CO₂ CH₄ ratio 2.8 0.76 0.16 0.07 0.01 4.6 3.8 0.770.14 0.09 0.00 5.4 4.5 0.77 0.13 0.10 0.00 6.1 5 0.77 0.12 0.11 0.00 6.56 0.78 0.10 0.12 — 7.8 * Corresponds to generation of 100 millionstandard cubic feet of syngas

Stream 13 can be obtained directly from a supply of natural gas ormethane. Alternatively, all or part of stream 13 can be obtained as thewaste gas or offgas from another chemical or refining operation, or fromsources such as landfill gas or digester gas. In some cases, all or aportion 125 of stream 25 (described later) can be directed to stream 13for use as a hydrocarbon feedstock or stream 14 for use as fuel forreformer 6. It is preferred to feed a stream 17 comprising at least oneof hydrogen, carbon monoxide and methane, to reactor 6 to be combustedas fuel to provide energy that is consumed in the reforming reaction.Stream 17 is described further below.

Streams 11 and 9 are combined to form mixed syngas stream 19, whichcontains hydrogen and carbon monoxide in a molar ratio of hydrogen tocarbon monoxide that is higher than the mole ratio of hydrogen to carbonmonoxide in stream 9. Preferably the mole ratio of hydrogen to carbonmonoxide in stream 19 is at least 1.1:1, preferably at least 1.5:1, andmore preferably at least 1.6:1. In other preferred embodiments, the moleratio of hydrogen to carbon monoxide in stream 19 is within 10% of 2:1,and even more preferably up to 2.2:1. This mole ratio can be higher than2.2:1, but at ratios higher than 2.2:1 the efficiency of the overallprocess begins to diminish because the production of the additionalhydrogen represented by the higher ratio comes at an energy cost that isnot fully compensated in the operation of the reactor 8. When thedesired product fuel is an alcohol such as ethanol, it is recommendedthat stream 19 contain no more than 10 vol. % carbon dioxide andpreferably no more than 7 vol. % carbon dioxide. Therefore, theprocesses by which streams 9 and 11 are produced, and the relativeamounts of streams 9 and 11 that are combined to form stream 19, shouldbe adjusted so that the carbon dioxide content of stream 19 iscontrolled to such desired values. Stream 19 is optionally compressed(not shown) before it is fed to reactor 8. (Streams 11, stream 9 and 11,and/or stream 19 could be depressurized through a valve or an expanderif the pressure required by unit 8 is less than the pressure of streams11 and/or 9.) The compression will be accompanied with a condensateremoval system, also not shown. It is conceivable that there could be anoptional carbon dioxide removal unit 201 ahead of reactor 8 to reducecarbon dioxide levels in stream 19 to less than 10 vol. % andpreferably, less than 7 vol. %. The carbon dioxide removal process canbe carried out with one of several commercial alternatives, whichtypically use a physical solvent (e.g. methanol) or a chemical solvent(alkanolamine), or which employ physical adsorbent technology such as aPSA or VPSA.

Typically stream 11 would comprise, on a dry basis, 55-80 mole %hydrogen, 10-30 mole % carbon monoxide, 5-20 mole % carbon dioxide, and1-8 mole % methane.

Optional carbon dioxide removal units 201 can be located in stream 19 orin stream 11, as shown in FIG. 1.

Stream 19 is then fed to reactor 8 wherein product fuel is produced.Preferably, product fuel is produced by a catalytic conversion process,e.g. Fischer-Tropsch process. However, the present invention isadvantageous also when the product fuel is produced by fermentation orother conversion mechanisms. Stream 19 will typically require somecompression before being fed to reactor 8 depending on the pressure ofstream 19. (Higher pressure gasifiers such as entrained flowtechnologies can result in stream 19 pressures sufficient for use inunit 8 without compression.). If the end-product is a diesel-type offuel, a single stage of compression may suffice. For alcohols, e.g.methanol, ethanol, 2-3 stages of compression may be required. Obviouslycompressing the blended stream 19 provides the benefit of a reduction inthe amount of equipment needed for compression versus separatelycompressing streams 11 and 9 to the desired pressure for reactor 8.

Considering Fischer-Tropsch conversion in general, the Fischer-Tropschreaction may be carried out in any reactor that can tolerate thetemperatures and pressures employed. The pressure in the reactor istypically between 300 psia and 1500 psia, while the temperature may bebetween 400° F. and 700° F. Preferably, the Fischer-Tropsch hydrocarbonsynthesis stage is a high temperature Fischer-Tropsch hydrocarbonsynthesis stage. The reactor will thus contain a Fischer-Tropschcatalyst, which will be in particulate form. The catalyst may contain,as its active catalyst component, Co, Fe, Ni, Ru, Re and/or Rh. Thecatalyst may be promoted with one or more promoters selected from analkali metal, V, Cr, Pt, Pd, La, Re, Rh, Ru, Th, Mn, Cu, Mg, K, Na, Ca,Ba, Zn and Zr. The catalyst may be a supported catalyst, in which casethe active catalyst component, e.g. Co, is supported on a suitablesupport such as alumina, titania, silica, zinc oxide, or a combinationof any of these.

In the Fischer-Tropsch conversion, the hydrogen and carbon monoxide instream 19 react under pressure in the presence of a catalyst at reactiontemperature in the indicated range to yield a mixture of alkanols,alkanes, or both, which may contain 1 to 50 carbon atoms. Water andcarbon dioxide are also produced.

As the Fischer-Tropsch reaction is exothermic, steam-producing coolingcoils are preferably present in the Fischer-Tropsch reactors to removethe heat of reaction. This steam can be fed to reactor 6 as part of thesteam reactant in the steam methane reforming reaction. Fresh catalystis preferably added to reactor 8 when required without disrupting theprocess to keep the conversion of the reactants high and to ensure thatthe particle size distribution of the catalyst particles is keptsubstantially constant.

The manner of carrying out a variation of the Fischer-Tropsch reactionfor producing alcohols from syngas is well known and has been practicedfor several years. Useful disclosure is found in “Synthesis of Alcoholsby Hydrogenation of Carbon Monoxide”. R. B. Anderson, J. Feldman and H.H. Storch, Industrial & Engineering Chemistry, Vol. 44, No. 10, pp2418-2424 (1952). Several patents also describe different aspects of theFischer-Tropsch conversion process that can be practiced to producealkanols including ethanol. For example, U.S. Pat. No. 4,675,344provides details on process conditions, e.g. temperature, pressure,space velocity, as well as catalyst composition to optimize theFischer-Tropsch process for increased production of C2 to C5 alcoholsversus methanol. This patent also indicates that a desirablehydrogen:carbon monoxide ratio in the gas feed stream is in the range of0.7:1 to 3:1. U.S. Pat. No. 4,775,696 discloses a novel catalystcomposition and a procedure for synthesis of alcohols via theFischer-Tropsch conversion. U.S. Pat. No. 4,831,060 and U.S. Pat. No.4,882,360 provide a comprehensive discussion on the preferred catalystcomposition and synthesis procedures for a producing a product mix witha higher ratio of C2-5 alcohols versus methanol. The catalyst istypically comprised of:

-   -   (1) A catalytically active metal of molybdenum, tungsten or        rhenium, in free or combined form;    -   (2) A co-catalytic metal of cobalt, nickel or iron, in free or        combined form;    -   (3) A Fischer-Tropsch promoter, e.g. alkali or alkaline earth        metals such as potassium;    -   (4) An optional support, e.g. alumina, silica gel, diatomaceous        earth.        Use of the above catalyst composition provides both high        production rates and high selectivities.

When the desired product fuel is methanol, the catalytic conversion isoperated in any manner known to favor the formation of methanol, such ascarrying out the reaction with a copper-zinc catalyst.

The overall stoichiometry for the production of alcohols from syngasusing the Fischer-Tropsch process can be summarized as follows(“Thermochemical Ethanol via Indirect Gasification and Mixed AlcoholSynthesis of Lignocellulosic Biomass”. S. Phillips, A. Aden, J. Jechura,D. Dayton and T. Eggeman Technical Report, NREL/TP-510-41168, April2007):nCO+2nH₂→C_(n)H₂₊₁OH+(n−1)H₂OAs can be seen from this stoichiometry, the optimal molar ratio ofhydrogen to carbon monoxide in the syngas is 2:1. A slightly lower ratiois compensated somewhat by the catalysts used in for mixed alcoholproduction (e.g. molybdenum sulfide), which are known to provide somewater-gas shift activity. Occurrence of the water-gas shift reaction,shown here:CO+H₂O→CO₂+H₂in the Fischer-Tropsch reactor effectively increases the hydrogen:carbonmonoxide ratio and correspondingly, increases conversion of syngas toethanol.

Stream 19 or a portion of stream 11 can if desired be fed into one ormore than one location in the reactor or reactors that form the desiredfuel (not shown).

The mixture of products formed in reactor 8 is represented in FIG. 1 asstream 21. This stream 21 is treated in product recovery unit 10 torecover stream 23 of the desired product fuel, such as ethanol, as wellas stream 25 of liquid and/or solid by-products (such as longer-chainalkanes and/or alkanols, e.g. naphtha), and stream 27 of gaseousbyproducts. Stage 10 is shown separate from reactor 8 but in practicethe Fischer-Tropsch/catalytic reaction and the ensuing separation ofproducts may be carried in one overall processing unit which includes aseries of more than one operation. Recovery of the desired product instage 10 is carried out by distillation or other separatory techniqueswhich are familiar to those experienced in this field.

Gaseous stream 27 comprises at least one of hydrogen, carbon monoxide,water vapor, and light hydrocarbons such as methane and/or C2-C8hydrocarbons with 0 to 2 oxygen atoms. For each component of stream 27,the entire amount thereof may have been formed in reactor 8, or theentire amount may have been fed to reactor 8 and not reacted therein, orthe amount of the component may be a combination of amounts formed andamounts fed to reactor 8 and not reacted therein. Stream 17, which is atleast a portion or possibly all of stream 27, is fed to reactor 6 asfuel (to generate heat that is consumed in the endothermic steam-methanereforming reaction), as reactant in the steam-methane reformingreaction, or both, as shown in FIG. 1, to promote the formation ofstream 11. Any of stream 27 that is not fed to reactor 6 constitutesstream 29 which is flared, combusted, or fed to another operation totake advantage of its components and/or its energy value. Additionally,all or a portion 125 (preferably liquid) of byproduct stream 25 can bedirected to stream 13 for use as hydrocarbon feedstock in reformer 6 orto stream 14 for use as fuel for reformer 6. This is especially the casewhen the desired product fuel is a long chain hydrocarbon or diesel andthus results in generation of naphtha in stream 25.

Steam (stream 31) formed from water stream 30 that is used to removeheat from reactor 8 can be optionally fed to gasification stage 2, oroptionally can be fed to reactor 6 as a reactant for the steam methanereforming reaction. Additional steam will be generated in the gascooling sections of units 4 and 6 that can be used along with or inplace of the steam generated in unit 8.

FIG. 2 shows an alternative embodiment, in which stream 5 produced inthe gasification stage 2 is partially oxidized in partial oxidationstage 22 by reaction with oxygen or oxygen-enriched air stream 24.Partial oxidation is carried out to convert tars, methane andhydrocarbon species, e.g. C₂H₄, C₃s, present in stream 5 to morehydrogen and carbon monoxide. This embodiment is preferred when theFischer-Tropsch reactor 8 generates a significant amount of methane andother light gaseous hydrocarbons as a by-product. This is especially thecase when the desired product from the Fischer-Tropsch reactor is alonger-chain hydrocarbon or diesel fuel. In this case, reactor 8typically operates at pressures in the range of 300-500 psia, which islower than the pressure for the case of methanol, ethanol or mixedalcohol production. It is to be noted that in some cases when thedesired product is an alcohol or mixture of alcohols, theFischer-Tropsch reactor 8 may generate methane and other light gaseoushydrocarbons as by-product and the embodiment shown in FIG. 2 may bepreferred over the embodiment shown in FIG. 1. Alternatively, unit 22could be unit based on autothermal reforming technology.

FIG. 7 shows additional alternative embodiments of the currentinvention, which are particularly useful when coal, petroleum coke, orthe like is used as gasifier hydrocarbon feedstock. Hydrocarbonfeedstock stream 50 (preferably as a stream of particulate solids thatmay or may not be mixed with water to form a slurry) is fed to gasifier100. Gasifier 100 is any commercially available gasifier that is used toconvert coal, petroleum coke, or similar hydrocarbon feed material tosyngas (e.g. those made by General Electric, Conoco Phillips, Shell,Siemens, etc.). Coal gasifiers typically operate at higher pressuresthan biomass gasification units. Operating pressures for coal gasifierstypically range from 300 to 1500 psig and more typically from 500 to1100 psig. Also, coal gasifiers are typically of the entrained-flowtype. Streams 3 and 5 are as defined above except that stream 3 will notcontain steam.

Unit 101 comprises syngas cleanup and cooling or heating depending onthe type of gasifier 100. For example, if gasifier 100 is anentrained-flow quench-cooled gasifier, then unit 101 will be a scrubberthat is used to remove particulates, halides and other contaminants. Aportion of the syngas stream 251 exiting unit 101 is stream 264 which iscombined with stream 57 (if stream 57 is present, as discussed herein)to form stream 252. Stream 252 is reacted in water-gas shift reactor 102where CO is converted to CO₂ according to the reaction given previously.A second portion of stream 251 is stream 253 which bypasses shiftreactor 102. The quantity of gas in stream 253 is set such that stream19 exhibits the desired H₂:CO ratio which is described herein. Productstream 254 from shift reactor 102 is combined with bypass stream 253 andsyngas stream 56 (if stream 56 is present, as discussed herein) to formstream 255 which is preferably fed to acid gas removal unit 213 whereacid gas such as hydrogen sulfide and carbon dioxide is removed asstream 62. If desired, carbon dioxide may be removed as stream 63separately from other acid gases in stream 62. Acid gas removal can becarried out with any commercially available technology (e.g. “Rectisol”or “Selexol” technology) based on physical solvents (e.g. methanol) orchemical solvents (e.g. alkanolamines). The quantity of CO₂ recoveredfrom stream 255 into stream 63 will depend on several factors includingminimum carbon sequestration requirements and market demand for CO₂ forapplications such as enhanced oil recovery (EOR).

The processing from stream 19 onward is generally as described inprevious embodiments. Typically, unit 8 comprises a chemical conversionprocess whereby syngas stream 19 is converted to desired hydrocarbonproducts along with gaseous and liquid hydrocarbon byproducts andwater-based liquid byproducts. Separation processes are utilized withinunit 10 to separate the desired hydrocarbon product 23 from liquid/solidhydrocarbon byproduct stream 25, gaseous hydrocarbon byproduct stream27, and water-based byproduct stream 65. All of or a portion 125 ofliquid byproduct stream 25 may be combined with reactor 6 hydrocarbonfeed stream 13 or with fuel stream 14, as indicated by dashed lines inFIG. 3. Similarly, all of or a portion 17 of gaseous hydrocarbonbyproduct stream 27 may be combined with reactor 6 hydrocarbon feedstream 13 or fuel stream 14. It is recognized that streams 25 and 27could constitute streams 13 or 14 in entirety. The total carbonconversion efficiency of the process is improved by recycling thehydrocarbon byproducts to reactor 6 for the production of syngas stream56 which eventually produces desired hydrocarbon product stream 23.

In the treatment of a gas stream derived from coal, coke, or bitumen,units 8 and 10 may represent several synthesis and separation stepsarranged in series or in parallel. For example, syngas stream 19 mayinitially be converted to an intermediate product that containsimpurities. The desired intermediate product will be separated fromunwanted byproducts within unit 10. The desired intermediate productwill be returned to unit 8 for further chemical conversion to desiredhydrocarbon product and byproducts. The desired hydrocarbon product willbe separated from the byproducts within unit 10. The total gaseoushydrocarbon byproducts can be combined to form stream 27 while the totalliquid hydrocarbon byproducts can be combined to form stream 25 and thetotal water-based byproducts can be combined to form stream 65. Thedesired hydrocarbon product will form stream 23. For example, unit 8could represent a Fischer-Tropsch synthesis reactor as has beendescribed previously. Alternatively, unit 8 could represent a methanolsynthesis reactor that is followed by a methanol-to-gasoline converter.The intermediate methanol product may be purified within unit 10 beforebeing sent back to the methanol-to-gasoline converter feed within unit8. These details are omitted from FIG. 3, but are familiar to thoseskilled in the art.

The operating pressure of reactor 6 should be optimized to balance theeffects of methane slip against syngas compression.

As mentioned above, in some embodiments, such as starting up, andinterruptions of syngas feed derived from the biomass or othercarbonaceous feed material, no syngas from stream 9 is fed to unit 8,and stream 11 provides 100% of stream 19.

Reference is now made to FIG. 3, which illustrates embodiments in whichall or a portion of stream 11 can be reacted in a reactor such as awater-gas shift reactor to produce a stream having a higher hydrogencontent, and a higher carbon dioxide content, than the stream that isfed to the reactor.

In these embodiments, a portion of stream 11 can be fed as stream 57into the biomass-derived syngas stream (shown as stream 9, 64 or 66) toform stream 52. The portion of stream 11 (which may be all of stream 11)that is not stream 57 constitutes stream 58. All of or a portion ofstream 58 is fed as stream 59 to reactor 104 where hydrogen-enrichedstream 61 is formed (such as by the well-known water gas shiftreaction). Stream 61 has a higher hydrogen content than stream 59, andcontains carbon dioxide (including carbon dioxide produced in reactor104). All of or a portion of stream 58 can bypass reactor 104 as stream60. Stream 56 is formed by combining streams 60 and 61.Hydrogen-enriched stream 54 can be taken from stream 56 and fed into thebiomass-derived syngas stream 9. Stream 56, or stream 53 which remainsof stream 56 after stream 54 is taken off, can be combined with stream51 to form stream 55.

Typically stream 61 would comprise, on a dry basis, 60-90 mole %hydrogen, 2-15 mole % carbon monoxide, 10-30 mole % carbon dioxide, and1-8 mole % methane.

The streams shown in FIG. 3 represent possible ways that ahydrogen-enriched stream from reactor 104 can be fed into a gaseousproduct stream described herein containing hydrogen and carbon monoxide,and/or into the syngas stream derived from biomass, and/or into themixed syngas stream described herein. At least one of streams 53, 54,and 57 must be flowing. Streams 54, 57, 59 and 60 if present arepreferably provided with controls represented as valves 154, 157, 159and 160, respectively, to control the amounts of gas flowing in each ofstreams 54, 57, 59 and 60, and to control whether any gas flows at allin each of these streams. It will be recognized that any one or two of:stream 57 and valve 157; stream 60 and valve 160; and streams 59 and 61,reactor 104, and valve 159; may be completely omitted.

As pointed out above, where streams that are to be combined havedifferent pressures, the stream that is at a lower pressure may besubjected to compression and condensate removal before the streams arecombined.

As the reaction in reactor 104 also produces carbon dioxide, it ispreferable to remove at least some of this carbon dioxide so that it isnot fed into reactor 8. The carbon dioxide removal can be carried out byfeeding stream 55 into carbon dioxide removal unit 103. Alternatively,depending on which streams shown in FIG. 3 are present and flowing,carbon dioxide removal units can be provided in other streams, such asunit 103A to which is fed stream 56 and which produces stream 53; unit103B to which is fed stream 64 (formed by combining stream 9 with stream54) and which unit produces stream 66; unit 103C to which is fed tostream 52 (formed by combining stream 57 with stream 64) and whichproduces stream 51; and/or unit 103D to which is fed stream 61 formed inreactor 104 and which produces stream 61D. If any of 103B, 103C, or 103are used to remove CO₂ then the CO₂ removal capability identified aspart of unit 4 would likely not be included.

Carbon dioxide removal can be carried out using any known availabletechnology (e.g. “Rectisol” or “Selexol” technology) based on physicalsolvents (e.g. methanol) or chemical solvents (e.g. alkanolamines) orphysical adsorbents (PSA or VPSA technology). The quantity of carbondioxide removed should be sufficient so that stream 19 fed to reactor 8does not contain amounts of carbon dioxide high enough to interfere withthe desired fuel production. Typically, the carbon dioxide content ofstream 19 should be less than 10 vol. % and more preferably less than 7vol. %. Carbon dioxide separated in any of units 103, 103A, 103B, 103Cand 103D (shown as 113) can be vented or used for other industrialoperations or for end-uses such as enhanced oil recovery. The carbondioxide content of any stream 113 is typically at least 90 vol. % on adry basis. A portion could be recycled to reactor 6 to reduce the H₂/COratio of stream 11.

FIG. 4 is similar to FIG. 3 and illustrates possibilities that takeadvantage of the production of the additional hydrogen that reactor 104produces. Optionally, one may wish to recover some of this producedhydrogen, while still leaving enough hydrogen in the system so thatstream 19 contains sufficient hydrogen relative to the carbon monoxidepresent so that the desired fuel production can be carried out inreactor 8.

Thus, in FIG. 4, reference numerals that also appear in FIG. 3 have thesame meanings as for FIG. 3. When it is desired to recover a separatestream having a high hydrogen content, units that separate a hydrogenproduct stream from the stream fed to the respective unit can be locatedat any of the locations shown in FIG. 3 as 103, 103A, 103B, 103C and103D. However, the preferred location for a unit to recover a hydrogenproduct stream is shown in FIG. 4 as 203D, and stream 213 represents thehydrogen product stream that is separately recovered. Hydrogen can beseparated from any of the feed streams shown in FIG. 4, by knowntechnology such as physical adsorption employing PSA (pressure swingadsorption) technology as shown in FIG. 5. Tail gas from 203D (FIG. 5stream 261) would be sent to unit 6 as fuel. Alternatively, 203D couldbe a membrane unit allowing 61D to be mixed with stream 60 to formstream 56. In this situation unit 103D shown in FIG. 3 would be placedafter 203D in stream 61D. With a PSA, the hydrogen content of any stream213 is typically at least 99 vol. % on a dry basis. If a polymericmembrane is used to produce hydrogen then stream 213 would need furtherprocessing (generally by a PSA) to provide hydrogen with lowconcentrations of CO plus CO₂ (generally the concentration is limited toless than 10 ppmv.) If an advanced hydrogen membrane based on materialsthat transport only hydrogen across the membrane (materials such aspalladium and palladium alloys) are used then no additional purificationwill be needed. In most cases, membrane separation units will requirecompression of the hydrogen stream prior to further processing or use.The hydrogen that is recovered can be used in other industrial orrefining operations including stage 10 or reactor 8.

FIG. 5 illustrates another embodiment, in which a portion of stream 11but less than all of stream 11 is fed as stream 58 to reactor 104 (suchas a water-gas shift reactor) which processes stream 58 to producestream 61 which has a higher hydrogen content than stream 58. Stream 61is fed to unit 203D which separates stream 61 into a hydrogen productstream 213, and a second product stream 261 which is fed to reactor 6.Unit 203D employs any known technology such as physical adsorptiontechnology, preferably PSA technology. The hydrogen that is recoveredcan be used in other industrial or refining operations including stage10 or reactor 8.

The present invention provides numerous advantages.

The invention increases conversion of carbon monoxide generated in thebiomass treatment step (e.g. the gasification step) to product fuelwhich increases the output of the desired product fuel, e.g. ethanol,methanol, diesel, by virtue of the increase in the hydrogen:carbonmonoxide ratio in the syngas fed to the catalytic/Fischer-Tropschreactor.

An advantage is that the methodology described herein can be adjusted,in that the processing conditions can be adjusted in response to changesin the characteristics of the biomass, or changes in the desired productfuel (i.e. changes in the relative proportions of the differentcomponents of the fuel produced).

Another advantage of the invention relates to the impact of the additionof the hydrogen-rich syngas stream 11 on the overall carbon footprint ofthe facility that transforms biomass into fuel, as quantified in termsof CO₂ emissions avoided. The fuel such as ethanol produced from thisfacility reduces anthropogenic CO₂ emissions by replacing an equivalentamount of gasoline used as fuel in automobiles. Thus, increasing thefuel (ethanol) output of the facility through addition of the relativelyhydrogen-rich stream 8 has a positive impact, i.e. net CO₂ emissionsavoided increases, even taking into account the likelihood that thehydrogen-rich stream is typically produced from a fossil fuel, e.g.natural gas, in a way that results in additional CO₂ emissions. Thepresent invention enables reliance on selecting the process conditionsfor the syngas production reactor (reactor 6) so as to maintain orpreferably increase the net CO₂ emissions avoided as compared to thebase gasified biomass-to-fuel process without addition of thehydrogen-rich syngas stream.

Among other advantages of the present invention, fewer unit operationsare needed for generation of the hydrogen-rich stream 11 versus morethan 99% H₂ (stream 35 in FIG. 6). The system for generating thehydrogen-rich stream 11 allows an easier way to optimize catalystselectivity to drive the liquid fuel-forming reactions instead ofreliance on the water-gas shift.

In addition, the present invention achieves these advantages at lowcapital cost owing to needing fewer and less complex unit operations ascompared to other possible approaches. Operating costs are reducedbecause of the increased fuel (e.g. ethanol) production from what isotherwise the same system.

There are alternatives to the source of stream 13 in addition to what isdescribed above.

For cases where the end product from the Fischer-Tropsch reactor is along-chain hydrocarbon or diesel fuel, byproduct stream 25 (see FIG. 2)contains naphtha. All or a portion 125 of this stream can be fed toreactor (reformer) 6 as fuel or feedstock.

For cases where methanol is the desired product from reactor 8, theremay be an accompanying downstream process (not shown) that convertsmethanol to gasoline. All or a portion of the liquefied petroleum gases(LPG) generated as a byproduct from the conversion of methanol togasoline can be fed to reactor 6 as feedstock (stream 13) and fuel(stream 14).

It should be recognized that in all the embodiments discussed that unit8 could receive enough syngas from unit 6 to remain operational eventhough unit 2 is not producing syngas.

Example 1

A simulation was based on a biomass-to-fuel facility assumed to process1500 tons/day of biomass. The biomass feedstock is assumed to have acarbon content of 40%. The biomass gasifier is assumed to operate at ahigh temperature, e.g. >2000° F. Consequently, the biomass-derivedsyngas is expected to contain negligible amounts of tar, methane andother hydrocarbons. For purposes of illustration here, the compositionof the biomass-derived syngas is assumed to be 44% CO, 2.4% CO₂, 49.1%H₂ and 4.5% H₂O. For the base case, i.e. no addition of stream 11 to thesyngas, the ethanol production is estimated to be 46.5 million gallonsper year. The conversion reactor is assumed to operate at 482° F. and1500 psia.

Two alternatives for hydrogen-rich streams were considered, so as toraise the H2:CO ratio in stream 19 (see FIG. 1) to 1.8:1:

-   -   1. Alternative 1: 23 MMSCFD of >99.9% H₂ (<10 ppm CO, CH₄, CO₂).        Such a stream can be produced by the system shown in FIG. 6,        which consists of a steam methane reformer 6 followed by a shift        reactor 34 and H₂ pressure swing adsorption 32. In this case,        the tail gas 33 from the pressure swing adsorption unit 32 is        recycled to the steam methane reformer 6 to be used as fuel to        be combusted to provide heat energy to the reforming reaction.        The stream containing >99.9% H₂ is blended with stream 9 prior        to feeding to conversion reactor 8.    -   2. Alternative 2: 55 MMSCFD of syngas containing 74.2% H₂, 15.9%        CO, 7.2% CO₂, 1.6% CH₄, 0.2% N₂, 0.9% H₂. Such a stream can be        generated by a steam methane reformer 6 as shown in FIG. 1. The        H₂-rich syngas stream 11 is blended with stream 9 prior to        feeding to conversion reactor 8. In this case, the tail gas        stream 27 from the conversion reactor is fed to the steam        methane reformer to be used as fuel to be combusted to provide        heat energy to the reforming reaction.

Table 2 illustrates the impact of addition of each of the twoalternative hydrogen-rich streams. Clearly, addition of either type ofhydrogen-rich stream enhances the ethanol output. However, addition ofthe hydrogen-rich syngas stream provides twice the increase in ethanoloutput, i.e. about 63% versus about 31% with addition of essentiallypure hydrogen. This translates to commensurate improvements in processyield (gallons of ethanol per ton of biomass fed) and in carbonconversion efficiency. Further, addition of hydrogen-rich syngas enablesan improvement in the carbon footprint, i.e. increases net CO₂ emissionsavoided by 90 tons/day versus the base case. For the case of purehydrogen addition, the CO₂ emissions in producing the hydrogen outweighthe benefits of reduced CO₂ emissions due to the additional ethanolbeing generated. Net CO₂ emissions avoided decreases by 145 tons/dayversus the base case. This trend can also be noted by tracking the tonsof CO₂ emissions avoided per ton of carbonaceous feed material (e.g.biomass) in each of the three cases.

It should also be recognized that using high-purity hydrogen to increasethe yield through raising the hydrogen to CO ratio does not enableoperation of the facility while the biomass syngas unit is unavailable.In addition, although steam would be made available during startup thehydrogen would not enable the start of the liquid production unit (8)until the biomass syngas generator becomes operational. The hydrogenwould need to be flared or used as a fuel while the biomass system ismade operational.

TABLE 2 Impact of addition of H2-rich stream to syngas fed to F-Tprocess for high temperature gasifier H2 Syngas Base Addition AdditionEthanol production, Million gallons per year 80 105 130 Process yield,gal ethanol/ton biomass 149 193 241 CO2 emissions avoided for equivalent1435 1865 2330 gasoline, tons/day CO2 emissions from fossil input togenerate 575 805 H2/syngas, tons/day Net CO2 emissions avoided, tons/day1435 1290 1525 Tons CO2 avoided per ton of biomass 0.96 0.86 1.02

Example 2

Example 2 is analogous to Example 1 with the key difference being thatthe gasifier is assumed to operate at a lower temperature, typically˜1500° F. Consequently, the biomass-derived gas stream 5 containssignificant amounts of methane, higher hydrocarbons (C2's, C2+) andtars. For purposes of illustration here, the composition of thebiomass-derived syngas is assumed to be 14% CO, 34% CO₂, 22% H₂, 13%H₂O, 15% CH₄ and 2% C₂H₄. Since a significant portion of the energy isin the form of hydrocarbons, the syngas stream 5 is directed to a POXreactor (see block 22 in FIG. 2) to enable reforming of thehydrocarbons. The resultant stream 105 has the composition 23.4% CO,25.5% CO₂, 30.5% H₂, 15.6% H₂O and 5% CH₄. Since the H2/CO ratio is 1.3,for the base case it is assumed that block 4 includes a shift reactor toshift adequate amounts of CO to H2 to raise the H2/CO ratio to 2:1 priorto feeding to reactor 8. In this case, with no addition of stream 11 tothe syngas, the ethanol production is estimated to be 53.9 milliongallons per year.

Two alternatives for hydrogen-rich streams were considered, identical tothose in Example 1. The amounts added were adjusted to increase theoverall H2/CO ratio in stream 19 to 2:1. Thus, the two alternativesconsidered were:

-   -   1. Alternative 1: 14.1 MMSCFD of >99.9% H₂ (<10 ppm CO, CH₄,        CO₂).    -   2. Alternative 2: 31.9 MMSCFD of syngas containing 74.2% H₂,        15.9% CO, 7.2% CO₂, 1.6% CH₄, 0.2% N₂, 0.9% H₂.        Table 3 illustrates the impact of addition of each of the two        hydrogen-rich streams. Increase in ethanol yield with the        addition of H2-rich syngas is twice that of the yield increase        with H2 addition. Further net CO2 emissions avoided increases by        82 tons/day with syngas addition versus the base case. By        contrast, net CO2 emissions avoided decreases by 74 tons/day        with H2 addition versus the base case.

TABLE 3 Impact of addition of H2-rich stream to syngas fed toFischer-Tropsch process for moderate temperature gasifiers H2 SyngasBase Addition Addition Biofuel production, Million gallons of ethanol53.9 69.6 87 equivalents per year Process yield, gal ethanol/ton biomass108 139 174 CO2 emissions avoided for equivalent 953 1231 1539 gasoline,tons/day CO2 emissions from fossil input to generate 352 504 H2/syngas,tons/day Net CO2 emissions avoided, tons/day 953 879 1035 Tons CO2avoided per ton of biomass 0.70 0.64 0.76Again as in the case with Example 1, it should be recognized that usinghydrogen to increase the yield through raising the hydrogen to CO ratiodoes not enable operation of the facility while the biomass syngas unitis unavailable. In addition, although steam would be made availableduring startup the hydrogen would not enable the start of the liquidproduction unit (8) until the biomass syngas generator becomesoperational. The hydrogen would need to be flared or used as a fuelwhile the biomass system is made operational.

What is claimed is:
 1. A method, comprising (A) providing fossil-fuelhydrocarbon feed; (B) forming from said fossil-fuel hydrocarbon feed agaseous product stream comprising hydrogen and carbon monoxide at a moleratio of H₂:CO of at least 2.0:1; (C) forming a syngas stream that isderived from carbonaceous feed material and subjecting this syngasstream to partial oxidation; (D) adding the gaseous product streamformed in step (B) to a the partially oxidized syngas stream derivedfrom carbonaceous feed material, in a sufficient amount to form a mixedsyngas stream having a H₂:CO mole ratio greater than that of saidpartially oxidized syngas stream derived from carbonaceous feedmaterial; (E) converting said mixed syngas stream to form product fueland recovering from said converting a byproduct stream comprising one ormore of hydrogen, CO, water vapor, methane, and hydrocarbons containing2 to 8 carbon atoms and 0 to 2 oxygen atoms; and (F) reacting up to 100%of said byproduct stream in said formation of said gaseous productstream in step (B).
 2. A method according to claim 1 wherein said syngasstream that is derived from carbonaceous feed material is derived bygasification.
 3. A method according to claim 1 wherein thefossil-fuel-based hydrocarbon feed provided in step (A) comprisesmethane.
 4. A method according to claim 1 wherein the fossil-fuel-basedhydrocarbon feed provided in step (A) comprises hydrocarbons containingup to 8 carbon atoms.
 5. A method according to claim 1 wherein thefossil-fuel-based hydrocarbon feed provided in step (A) comprises LPG.6. A method according to claim 1 wherein said gaseous product stream isformed by steam-methane reforming.
 7. A method according to claim 1wherein said gaseous product stream is formed by secondary reforming ofa stream that is formed by steam-methane reforming.
 8. A methodaccording to claim 7 wherein the secondary reforming is autothermalreforming.
 9. A method according to claim 1 wherein said gaseous productstream is formed by autothermal reforming.
 10. A method according toclaim 1 wherein said gaseous product stream is formed by non-catalyticpartial oxidation.
 11. A method according to claim 1 wherein the moleratio of hydrogen:carbon monoxide in the mixed syngas stream formed instep (C) is at least 1.5:1.
 12. A method according to claim 1 whereinsaid combined stream is converted in step (D) to product fuel by aFischer-Tropsch reaction.
 13. A method according to claim 1 wherein saidfuel formed in step (D) comprises alkanol containing up to 5 carbonatoms.
 14. A method according to claim 1 wherein up to 100% of abyproduct stream produced in step (D) is fed to step (B) and iscombusted to produce heat which is consumed in the formation of saidgaseous product stream in step (B).
 15. A method according to claim 1wherein up to 100% of a byproduct stream produced in step (D) is fed tostep (B) and is reacted in the formation of said gaseous product streamin step (B).
 16. A method according to claim 2 further comprisingevaporating a feed stream of water with heat produced by the conversionof said mixed syngas stream in step (D) to produce steam and using up toall of said steam in said gasification of carbonaceous feed material.17. A method according to claim 1 further comprising evaporating a feedstream of water with heat produced by the conversion of said mixedsyngas stream in step (D) to produce steam and reacting up to all ofsaid steam with fossil-fuel-based hydrocarbon feed in step (B).
 18. Amethod according to claim 1 further comprising (I) treating a portion upto 100% of the gaseous product stream formed in step (B) to produce ahydrogen-enriched stream which contains hydrogen at a hydrogen contentgreater than that of said gaseous product stream and which also containscarbon dioxide, (II) adding the hydrogen-enriched stream to one or moreof (i) said gaseous product stream, (ii) said syngas stream derived fromcarbonaceous feed material, or (iii) said mixed syngas stream, and (III)removing carbon dioxide from said mixed syngas stream, from saidhydrogen-enriched stream, or from any of streams (i) or (ii) to whichsaid hydrogen-enriched stream is added.
 19. A method according to claim1 further comprising (I) treating a portion up to 100% of the gaseousproduct stream formed in step (B) to produce a hydrogen-enriched streamhaving a hydrogen content greater than that of said gaseous productstream as well as carbon dioxide, and (II) recovering hydrogen from saidhydrogen-enriched stream.
 20. A method for improving the carbonconversion efficiency of fuel production from carbonaceous feedmaterial, comprising (A) deriving a raw gaseous stream comprisinghydrogen and carbon monoxide in a mole ratio of hydrogen:carbon monoxideof less than 2:1 from carbonaceous feed material; (B) forming a secondgaseous stream comprising hydrogen and carbon monoxide in a mole ratioof hydrogen:carbon monoxide greater than 2:1 and also comprising carbondioxide, and combining said second gaseous stream and the stream derivedin step (A); (C) converting said combined stream into liquid productfuel, and a gaseous byproduct mixture comprising hydrogen, carbonmonoxide, water vapor and methane; (D) reacting hydrocarbon fuel andsteam to form said second gaseous stream, wherein at least a portion ofsaid gaseous byproduct mixture is combusted to produce heat which isconsumed in said reaction.
 21. A method, comprising: (A) providingfossil-fuel hydrocarbon feed to a reactor; (B) forming from saidfossil-fuel hydrocarbon feed a gaseous product stream comprisinghydrogen and carbon monoxide at a mole ratio of H₂:CO of at least 2.0:1;(C) converting up to all of said gaseous product stream to form productfuel and recovering from said converting a byproduct stream comprisingone or more of hydrogen, CO, water vapor, methane, and hydrocarbonscontaining 2 to 8 carbon atoms and 0 to 2 oxygen atoms; and (D) reactingup to 100% of said byproduct stream in said formation of said gaseousproduct stream in step (B); wherein steps (A)-(D) are performedsequentially without adding to said gaseous product stream any othergaseous product derived from carbonaceous feed material; and thereafter(E) forming a syngas stream containing hydrogen and CO that is derivedfrom carbonaceous feed material, in a sufficient amount to form a mixedsyngas stream having a H₂:CO mole ratio greater than that of said syngasstream derived from carbonaceous feed material and adding the gaseousproduct stream formed in step (B) to the syngas derived fromcarbonaceous feed material in this step (E); (F) converting said mixedsyngas stream to form product fuel and recovering from said converting abyproduct stream comprising one or more of hydrogen, CO, water vapor,methane, and hydrocarbons containing 2 to 8 carbon atoms and 0 to 2oxygen atoms; and (G) reacting up to 100% of said byproduct stream insaid formation of said gaseous product stream in step (B).
 22. A methodaccording to claim 21, wherein steps (A) through (G) are preceded by thesteps of (a) providing fossil-fuel hydrocarbon feed; (b) forming fromsaid fossil-fuel hydrocarbon feed a gaseous product stream comprisinghydrogen and carbon monoxide at a mole ratio of H₂:CO of at least 2.0:1;(c) adding the gaseous product stream formed in step (b) to a syngasstream containing hydrogen and CO that is derived from carbonaceous feedmaterial, in a sufficient amount to form a mixed syngas stream having aH₂:CO mole ratio greater than that of said syngas stream derived fromcarbonaceous feed material; (d) converting said mixed syngas stream toform product fuel and recovering from said converting a byproduct streamcomprising one or more of hydrogen, CO, water vapor, methane, andhydrocarbons containing 2 to 8 carbon atoms and 0 to 2 oxygen atoms; and(e) reacting up to 100% of said byproduct stream in said formation ofsaid gaseous product stream in step (b).
 23. The method of claim 21,wherein the gaseous product stream formed from said fossil-fuelhydrocarbon comprises hydrogen to carbon monoxide at a mole ratio ofH₂:CO in a range of about 2.0:1 to 10:1.